Utkarsh Vijayvargia, M. Jamiolahmady, Ayman R Nakhli, Ng Khai Yi
Hydraulic fracturing stimulation is considered a successful development technique in tight gas reservoirs. However, these expensive operations sometime underperform due to ineffective fracture fluid (FF) clean-up. This paper concentrates on FF clean-up efficiency for a Multiple Fractured Horizontal Well (MFHW) completed in both homogeneous and naturally fractured (NF) tight gas reservoirs. The emphasis is on NF reservoirs that make up a large percentage of tight gas assets, as their clean-up efficiency has received little attention. In this study, two numerical simulation models, i.e. a single-porosity single-permeability and a dual porosity-dual permeability model representing a homogeneous and a NF tight gas reservoir respectively, were used. Simulations were conducted on a MFHW with seven hydraulic fractures (HF). The process comprised of injection of FF, then a soaking time (ST) followed by production. The impact of various parameters which includes ST, FF viscosity, pressure drawdown and parameters pertinent to relative permeability and capillary pressure in matrix, hydraulic and natural fractures, were evaluated. In addition, based on a newly proposed treatment process that generates in-situ pressure and thermal energy that breaks gel viscosity, the effect of resultant viscosity reduction and local pressure increase, for improving the clean-up efficiency was also assessed. In these simulations, and due to uncertainty in its value, NF permeability was varied over a wide range. For conclusive purposes, Gas Production Loss i.e. GPL (%) defined as the difference in total gas production between the completely clean and un-clean cases as a percentage of the clean case, after a specific production period was used. This paper prioritizes the impact of pertinent parameters and highlights the influence of thermochemicals on the clean-up efficiency thereby justifying its commercial practicality. For instance, it is shown that the presence of NFs results initially in higher GPL but then GPL reduces significantly. Reducing the FF viscosity improves clean-up significantly especially for the NF models as NFs are the main contributor to the gas and FF flow from the reservoir to surface via hydraulic fractures. The sometimes non- monotonic trend of GPL variations, depends on the specific combination of NFs’ permeability and FF viscosity which results in the certain fluid invasion profile and mobility in the system. The paper emphasis is on the impact of thermochemicals and natural fractures on the cleanup up efficiency of hydraulic fracturing stimulations that should be optimized to reduce cost, thereby increasing the profit from these projects.
{"title":"Clean-Up Efficiency of Multiple Fractured Horizontal Wells Enhanced by Reactive Chemicals in Tight Gas Homogeneous & Naturally Fractured Reservoirs","authors":"Utkarsh Vijayvargia, M. Jamiolahmady, Ayman R Nakhli, Ng Khai Yi","doi":"10.2118/195147-MS","DOIUrl":"https://doi.org/10.2118/195147-MS","url":null,"abstract":"\u0000 Hydraulic fracturing stimulation is considered a successful development technique in tight gas reservoirs. However, these expensive operations sometime underperform due to ineffective fracture fluid (FF) clean-up. This paper concentrates on FF clean-up efficiency for a Multiple Fractured Horizontal Well (MFHW) completed in both homogeneous and naturally fractured (NF) tight gas reservoirs. The emphasis is on NF reservoirs that make up a large percentage of tight gas assets, as their clean-up efficiency has received little attention.\u0000 In this study, two numerical simulation models, i.e. a single-porosity single-permeability and a dual porosity-dual permeability model representing a homogeneous and a NF tight gas reservoir respectively, were used. Simulations were conducted on a MFHW with seven hydraulic fractures (HF). The process comprised of injection of FF, then a soaking time (ST) followed by production. The impact of various parameters which includes ST, FF viscosity, pressure drawdown and parameters pertinent to relative permeability and capillary pressure in matrix, hydraulic and natural fractures, were evaluated.\u0000 In addition, based on a newly proposed treatment process that generates in-situ pressure and thermal energy that breaks gel viscosity, the effect of resultant viscosity reduction and local pressure increase, for improving the clean-up efficiency was also assessed. In these simulations, and due to uncertainty in its value, NF permeability was varied over a wide range. For conclusive purposes, Gas Production Loss i.e. GPL (%) defined as the difference in total gas production between the completely clean and un-clean cases as a percentage of the clean case, after a specific production period was used. This paper prioritizes the impact of pertinent parameters and highlights the influence of thermochemicals on the clean-up efficiency thereby justifying its commercial practicality. For instance, it is shown that the presence of NFs results initially in higher GPL but then GPL reduces significantly. Reducing the FF viscosity improves clean-up significantly especially for the NF models as NFs are the main contributor to the gas and FF flow from the reservoir to surface via hydraulic fractures. The sometimes non- monotonic trend of GPL variations, depends on the specific combination of NFs’ permeability and FF viscosity which results in the certain fluid invasion profile and mobility in the system.\u0000 The paper emphasis is on the impact of thermochemicals and natural fractures on the cleanup up efficiency of hydraulic fracturing stimulations that should be optimized to reduce cost, thereby increasing the profit from these projects.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"15 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85692067","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Omar Al-Fatlawi, Mofazzal Hossain, N. Patel, A. Kabir
Hydraulic fracturing is considered to be a vital cornerstone in decision making of unconventional reservoirs. With an increasing level of development of unconventional reservoirs, many questions have arisen regarding enhancing production performance of tight carbonate reservoirs, especially the evaluation of the potential for adapting multistage hydraulic fracturing technology in tight carbonate reservoirs to attain an economic revenue. In this paper we present a feasibility study of multistage fractured horizontal well in typical tight carbonate reservoirs covering different values of permeability. We show that NPV is the suitable objective function for deciding on the optimum number of fractures and fracture half-length. Multistage fractured horizontal well has been found to be a feasible technique to produce from tight carbonate reservoirs with permeability in the range of 0.01-0.05 mD, while it is not economic reservoirs with permeability of around 0.001 mD. In addition, our study suggests that for feasibility study purposes simplified homogeneous reservoir models can be used instead of a heterogeneous one without compromising the quality of conclusions. This will save time, money and efforts in evaluating production performance of various options like, number, length and other fracture properties of multistage fractured horizontal wells.
{"title":"Evaluation of the Potentials for Adapting the Multistage Hydraulic Fracturing Technology in Tight Carbonate Reservoir","authors":"Omar Al-Fatlawi, Mofazzal Hossain, N. Patel, A. Kabir","doi":"10.2118/194733-MS","DOIUrl":"https://doi.org/10.2118/194733-MS","url":null,"abstract":"\u0000 Hydraulic fracturing is considered to be a vital cornerstone in decision making of unconventional reservoirs. With an increasing level of development of unconventional reservoirs, many questions have arisen regarding enhancing production performance of tight carbonate reservoirs, especially the evaluation of the potential for adapting multistage hydraulic fracturing technology in tight carbonate reservoirs to attain an economic revenue.\u0000 In this paper we present a feasibility study of multistage fractured horizontal well in typical tight carbonate reservoirs covering different values of permeability. We show that NPV is the suitable objective function for deciding on the optimum number of fractures and fracture half-length. Multistage fractured horizontal well has been found to be a feasible technique to produce from tight carbonate reservoirs with permeability in the range of 0.01-0.05 mD, while it is not economic reservoirs with permeability of around 0.001 mD. In addition, our study suggests that for feasibility study purposes simplified homogeneous reservoir models can be used instead of a heterogeneous one without compromising the quality of conclusions. This will save time, money and efforts in evaluating production performance of various options like, number, length and other fracture properties of multistage fractured horizontal wells.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82369610","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Rozlan, W. C. Hamat, M. F. Ishak, Jennie Chin, Joel Gil, C. K. Tan, Maisara Arsat, Saeid Elshourbagi, Syakura A. Rahim, Khairunnisa Ahmad, A. Ismail, Truong Son Nguyen, A. F. A. Pauzi, M. Jabar, Afzan A Satar, M. Misron
Downhole sand exclusion is becoming an essential sandface completion concept for brown fields in Peninsular Malaysia Oil Fields as reservoir pressure declines and formation sand weakens with production and water breakthrough. Additionally, multi-stack reservoirs require good zonal isolation to prevent cross flow between reservoirs with different pressure regime and to ensure gas and water breakthrough is delayed as long as possible. As such, Cased Hole Gravel Pack (CHGP) is the preferred method in many Malaysian fields. However, a lot of marginal fields become uneconomic due to the high cost and complexity of CHGP. Therefore, reducing CHGP’s cost and time becomes vital to ensure that projects improve the economics while at the same time ensuring good productivity from the reservoir. Traditionally, CHGP is performed zone-by-zone whereby the process of sump packer installation, perforation run, deburr run, gravel pack assembly installation and gravel pumping is repeated for each zone. In most cases, fluid loss pill which induces impairment of the formation is required. The paper will highlight on the Alternate Path System (APS) which enables single trip multiple-zone gravel packing whereby a repetitive process is only performed once. Gravel mixed continuously with low friction viscoelastic surfactant fluid allows for transportation to the lower zones via shunt-tubes attached to the screens even at extended shunt length. The APS system is then combined with Drill Stem Test (DST) and Tubing Conveyed Perforating (TCP) equipment to make a whole system of Single Trip Multizone Perforation and Pack (STPP) STPP technology was deployed in a campaign of four deviated and high temperature oil wells in a marginal field whereby the rig time saving was up to three days per well translating to almost USD 1 MM of cost saving which boosted project’s economics. Furthermore, STPP technique allows for gravel packing operation without fluid loss pill and less completion fluid loss in the formation which translates to better formation productivity and less impairment. Premature setting of GP Packer in one of the wells due to rupture disc failure within STPP system is the first such occurrence in the world. A lesson learned on how to ensure that it will not be repeated will be shared with all attendees.
{"title":"Single Trip Multizone Perforation and Gravel Pack STPP: Success Story and Lessons Learned in Malaysian Application","authors":"M. Rozlan, W. C. Hamat, M. F. Ishak, Jennie Chin, Joel Gil, C. K. Tan, Maisara Arsat, Saeid Elshourbagi, Syakura A. Rahim, Khairunnisa Ahmad, A. Ismail, Truong Son Nguyen, A. F. A. Pauzi, M. Jabar, Afzan A Satar, M. Misron","doi":"10.2118/194801-MS","DOIUrl":"https://doi.org/10.2118/194801-MS","url":null,"abstract":"\u0000 \u0000 \u0000 Downhole sand exclusion is becoming an essential sandface completion concept for brown fields in Peninsular Malaysia Oil Fields as reservoir pressure declines and formation sand weakens with production and water breakthrough. Additionally, multi-stack reservoirs require good zonal isolation to prevent cross flow between reservoirs with different pressure regime and to ensure gas and water breakthrough is delayed as long as possible. As such, Cased Hole Gravel Pack (CHGP) is the preferred method in many Malaysian fields. However, a lot of marginal fields become uneconomic due to the high cost and complexity of CHGP. Therefore, reducing CHGP’s cost and time becomes vital to ensure that projects improve the economics while at the same time ensuring good productivity from the reservoir.\u0000 \u0000 \u0000 \u0000 Traditionally, CHGP is performed zone-by-zone whereby the process of sump packer installation, perforation run, deburr run, gravel pack assembly installation and gravel pumping is repeated for each zone. In most cases, fluid loss pill which induces impairment of the formation is required. The paper will highlight on the Alternate Path System (APS) which enables single trip multiple-zone gravel packing whereby a repetitive process is only performed once. Gravel mixed continuously with low friction viscoelastic surfactant fluid allows for transportation to the lower zones via shunt-tubes attached to the screens even at extended shunt length. The APS system is then combined with Drill Stem Test (DST) and Tubing Conveyed Perforating (TCP) equipment to make a whole system of Single Trip Multizone Perforation and Pack (STPP)\u0000 \u0000 \u0000 \u0000 STPP technology was deployed in a campaign of four deviated and high temperature oil wells in a marginal field whereby the rig time saving was up to three days per well translating to almost USD 1 MM of cost saving which boosted project’s economics. Furthermore, STPP technique allows for gravel packing operation without fluid loss pill and less completion fluid loss in the formation which translates to better formation productivity and less impairment.\u0000 \u0000 \u0000 \u0000 Premature setting of GP Packer in one of the wells due to rupture disc failure within STPP system is the first such occurrence in the world. A lesson learned on how to ensure that it will not be repeated will be shared with all attendees.\u0000","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"332 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73139476","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Ping Chen, S. Rawlins, T. Hagen, Martijn Huijgen, David Yue, M. Hamam, H. E. Hajj, Tawfik Al-Ghamdi
A strategy combining fracturing and downhole scale inhibitor squeeze treatments was employed in an extremely tight high-temperature gas reservoir (200°C) with calcite and sulfate scaling problems. Challenges included developing a scale inhibitor that is thermally stable at this high temperature, fully compatible with the fracture fluid used, extremely beneficial with a low minimum effective concentration, with good adsorption/desorption properties for a long squeeze treatment life. Literature survey verifies that few reports are published discussing application of a combined fracture and downhole scale inhibitor squeeze treatment under such high-temperature reservoir conditions. Multiple laboratory tests were performed to qualify the scale inhibitor, including inhibitor dynamic tube blocking, static beaker, and fracture fluid property testing. Standard inhibition tests were adapted to confirm tests were designed to confirm that the scale inhibitor was thermally stable under application conditions (i.e., the scale inhibitor was blended with the fracture fluid (including breaker) at given concentrations and aged together at 200°C for a certain period). The aged scale inhibitor sample was then tested for its performance against scale and results compared to the unaged inhibitor sample. Further tests were designed for fracture fluid rheology and breaking time with the blended scale inhibitor to help ensure the scale inhibitor was fully compatible with the fracturing fluid and would not interfere with its properties. Laboratory test results demonstrated that the scale inhibitor is fully compatible with the fracturing fluid and formation brine. An extremely low minimum effective concentration of the scale inhibitor was determined to be 5 ppm with the aged and unaged scale inhibitor samples. With the addition of the scale inhibitor, the breaking time and rheology property of the fracture gel met all application requirements. The chemistry of the amine-containing polymer inhibitor and advantages of using this chemistry as a downhole squeeze product are discussed. Successful field treatment with the combined scale inhibitor and fracture fluid was conducted. A new scale inhibitor chemistry was developed for a high-temperature reservoir for combined fracture and downhole inhibitor squeeze treatments.
{"title":"Developing a Polymer Scale Inhibitor for a Combined Fracture and Inhibitor Squeeze Treatment for High-Temperature Reservoirs","authors":"Ping Chen, S. Rawlins, T. Hagen, Martijn Huijgen, David Yue, M. Hamam, H. E. Hajj, Tawfik Al-Ghamdi","doi":"10.2118/194929-MS","DOIUrl":"https://doi.org/10.2118/194929-MS","url":null,"abstract":"\u0000 A strategy combining fracturing and downhole scale inhibitor squeeze treatments was employed in an extremely tight high-temperature gas reservoir (200°C) with calcite and sulfate scaling problems. Challenges included developing a scale inhibitor that is thermally stable at this high temperature, fully compatible with the fracture fluid used, extremely beneficial with a low minimum effective concentration, with good adsorption/desorption properties for a long squeeze treatment life. Literature survey verifies that few reports are published discussing application of a combined fracture and downhole scale inhibitor squeeze treatment under such high-temperature reservoir conditions.\u0000 Multiple laboratory tests were performed to qualify the scale inhibitor, including inhibitor dynamic tube blocking, static beaker, and fracture fluid property testing. Standard inhibition tests were adapted to confirm tests were designed to confirm that the scale inhibitor was thermally stable under application conditions (i.e., the scale inhibitor was blended with the fracture fluid (including breaker) at given concentrations and aged together at 200°C for a certain period). The aged scale inhibitor sample was then tested for its performance against scale and results compared to the unaged inhibitor sample. Further tests were designed for fracture fluid rheology and breaking time with the blended scale inhibitor to help ensure the scale inhibitor was fully compatible with the fracturing fluid and would not interfere with its properties.\u0000 Laboratory test results demonstrated that the scale inhibitor is fully compatible with the fracturing fluid and formation brine. An extremely low minimum effective concentration of the scale inhibitor was determined to be 5 ppm with the aged and unaged scale inhibitor samples. With the addition of the scale inhibitor, the breaking time and rheology property of the fracture gel met all application requirements. The chemistry of the amine-containing polymer inhibitor and advantages of using this chemistry as a downhole squeeze product are discussed. Successful field treatment with the combined scale inhibitor and fracture fluid was conducted.\u0000 A new scale inhibitor chemistry was developed for a high-temperature reservoir for combined fracture and downhole inhibitor squeeze treatments.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"41 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76827855","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
To validate the completion model, a computer simulation was performed in four scenarios to predict mechanical failure limits. Consequently, a completion design model was obtained using vacuum-insolated tubing (VIT) that enables a minimum of 75% of steam quality given an inlet steam quality of 80%. In addition, a seal bore is used at 50° to 60° of inclination, which enables the upper completion disconnection/connection through the seal stinger at that depth, without losing production capabilities for changes in the depth of top of connection of tie-back. This paper describes the type of completion development and challenges encountered during the design. The advantages and benefits of collecting the correct information in the process of thermal recovery in the joint venture are also discussed. The investigation resulted in a completion model of thermal wells that will enable the monitoring of the conditions of the injection, tubing, casing, and injection effectiveness in the system in which the cyclic process is applied and adjusted to wells in the Orinoco Belt. A conclusion of this investigation is that, during the injection, the movement of production string and the monitoring component must be independent to avoid the transference of stress resulting from thermal expansion. Polished bore receptacles and seal assemblies should be used in the replacement of expansion joints; this will enable the upper completion to be used for recovery and changed for the injection system. Although completion models have been developed in which the steam path can be monitored, they have not been developed previously for use in long horizontal section wells, as was performed in this case. The problem of thermal expansion of the tubing during steam injection is expected to be resolved with the implementation of the design based on this study. Feed-through packers have already been developed especially for this process, although with a mixed record of successful and unsuccessful deployments. The monitoring system must be mechanically independent of the injection system, such that movements associated with expansion and contraction do not have a significant effect.
{"title":"Development of a Completion Model for the Monitoring of EOR in Wells with Heavy and Extra Heavy Crude in the Largest Deposit in Latin America","authors":"G. Peña, Deivy Patiño","doi":"10.2118/194830-MS","DOIUrl":"https://doi.org/10.2118/194830-MS","url":null,"abstract":"\u0000 To validate the completion model, a computer simulation was performed in four scenarios to predict mechanical failure limits. Consequently, a completion design model was obtained using vacuum-insolated tubing (VIT) that enables a minimum of 75% of steam quality given an inlet steam quality of 80%. In addition, a seal bore is used at 50° to 60° of inclination, which enables the upper completion disconnection/connection through the seal stinger at that depth, without losing production capabilities for changes in the depth of top of connection of tie-back. This paper describes the type of completion development and challenges encountered during the design. The advantages and benefits of collecting the correct information in the process of thermal recovery in the joint venture are also discussed.\u0000 The investigation resulted in a completion model of thermal wells that will enable the monitoring of the conditions of the injection, tubing, casing, and injection effectiveness in the system in which the cyclic process is applied and adjusted to wells in the Orinoco Belt. A conclusion of this investigation is that, during the injection, the movement of production string and the monitoring component must be independent to avoid the transference of stress resulting from thermal expansion. Polished bore receptacles and seal assemblies should be used in the replacement of expansion joints; this will enable the upper completion to be used for recovery and changed for the injection system.\u0000 Although completion models have been developed in which the steam path can be monitored, they have not been developed previously for use in long horizontal section wells, as was performed in this case. The problem of thermal expansion of the tubing during steam injection is expected to be resolved with the implementation of the design based on this study. Feed-through packers have already been developed especially for this process, although with a mixed record of successful and unsuccessful deployments. The monitoring system must be mechanically independent of the injection system, such that movements associated with expansion and contraction do not have a significant effect.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78276486","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Xiaoer Chen, K. Fan, Chenghao Ren, Le Li, Zhenqian Yan, Guo-Fu Zou, Zhonglin Cao, Yao Zhao
The Cambrian Longwangmiao Formation in the Sichuan Basin, southwest China, mainly comprising of dolomites, is one of the most ancient production layer in the world. Recently, Anyue gas field was discovered in the Leshan-longnvsi paleo-uplift in the central Sichuan Basin, and become the oldest gas field in the carbonate rocks in a single structural system in China. The reservoir is mainly distributed in the shoal grain dolomite, which is always controlled by the sedimentary environment. The conventional well correlation and sedimentary facies analysis might result in difficulty of carbonate shoals distribution and reservoir description in the gas field. Hence, how to characterize the geometry and distribution of carbonate shoals is critical for gas exploration and development. In our study, we completed an interpretation of 1172km2 3D seismic data in the field by means of all reflectors auto-tracking method. The method, combining density-based spatial clustering with waveform similarity clustering algorithm, can automatically track and interpret all reflectors within the 3D seismic cube. As a result, 18 local horizons, characterized by a shingled progradational configuration, were recognized within the Longwangmiao Formation. Synthetic seismograms suggest that these parallel oblique progradational sets were considered as carbonate shoals. The Longwangmiao Formation is consisted of stacked multistaged carbonate grainstones deposited on the shoals within the platform. These shoals, which grow towards northwest, are approximately distributed surrounding the Leshan-Longnvsi paleo-uplift. Stacked and widely distributed shoal grainstone reservoir is formed on the uplift. Our study suggests that the paleo-uplift mainly controls the shoal distribution in the study area, which provides important clues for gas exploration.
{"title":"Application of All Reflectors Auto-Tracking Method to Characterize the Geometry and Distribution of Carbonate Shoals: An Example from the Lower Cambrian Longwangmiao Formation in the Moxi area, Sichuan Basin, Southwestern China","authors":"Xiaoer Chen, K. Fan, Chenghao Ren, Le Li, Zhenqian Yan, Guo-Fu Zou, Zhonglin Cao, Yao Zhao","doi":"10.2118/194796-MS","DOIUrl":"https://doi.org/10.2118/194796-MS","url":null,"abstract":"\u0000 The Cambrian Longwangmiao Formation in the Sichuan Basin, southwest China, mainly comprising of dolomites, is one of the most ancient production layer in the world. Recently, Anyue gas field was discovered in the Leshan-longnvsi paleo-uplift in the central Sichuan Basin, and become the oldest gas field in the carbonate rocks in a single structural system in China. The reservoir is mainly distributed in the shoal grain dolomite, which is always controlled by the sedimentary environment. The conventional well correlation and sedimentary facies analysis might result in difficulty of carbonate shoals distribution and reservoir description in the gas field. Hence, how to characterize the geometry and distribution of carbonate shoals is critical for gas exploration and development. In our study, we completed an interpretation of 1172km2 3D seismic data in the field by means of all reflectors auto-tracking method. The method, combining density-based spatial clustering with waveform similarity clustering algorithm, can automatically track and interpret all reflectors within the 3D seismic cube. As a result, 18 local horizons, characterized by a shingled progradational configuration, were recognized within the Longwangmiao Formation. Synthetic seismograms suggest that these parallel oblique progradational sets were considered as carbonate shoals. The Longwangmiao Formation is consisted of stacked multistaged carbonate grainstones deposited on the shoals within the platform. These shoals, which grow towards northwest, are approximately distributed surrounding the Leshan-Longnvsi paleo-uplift. Stacked and widely distributed shoal grainstone reservoir is formed on the uplift. Our study suggests that the paleo-uplift mainly controls the shoal distribution in the study area, which provides important clues for gas exploration.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"39 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89226892","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The development of deep oil and gas reservoirs requires high temperature stable drilling fluid systems. The properties of conventional polymers in water-based systems decline above 300°F which led to the development of the new high temperature water-based system. The high temperature water-based system, featuring a newly developed synthetic polymer, has been developed to provide enhanced rheological profiles and fluid loss control, along with long-term stability under elevated temperature and pressure conditions. The system has been designed to minimize formation damage by forming a thin and ultra-low permeable filter cake. The versatility of the developed polymer allows the new system to be formulated at a wide range of densities using most conventional oilfield brines including monovalent and divalent halide and formate brines. The clay-free high temperature drilling fluid has stable rheological properties, no gelation and low sag tendencies which are ideal for high temperature logging applications. Also, the highly branched nature of the polymer provides a rheological profile suitable for coil tubing applications. A new breaker package was developed along with the high temperature water-based system to slowly and uniformly clean-up its deposited filter cake, reducing near wellbore damage and maximizing production when the system is used to drill open-hole completion wells. This paper summarizes the fluid design in the lab and recent field applications, where the new high temperature polymer-based system was successfully deployed in different locations around the world.
{"title":"Multifunctional High Temperature Water-Based Fluid System","authors":"Balakrishnan Panamarathupalayam, Cedric Manzoleloua, Linus Sebelin, Tint Htoo Aung","doi":"10.2118/195009-MS","DOIUrl":"https://doi.org/10.2118/195009-MS","url":null,"abstract":"\u0000 The development of deep oil and gas reservoirs requires high temperature stable drilling fluid systems. The properties of conventional polymers in water-based systems decline above 300°F which led to the development of the new high temperature water-based system.\u0000 The high temperature water-based system, featuring a newly developed synthetic polymer, has been developed to provide enhanced rheological profiles and fluid loss control, along with long-term stability under elevated temperature and pressure conditions. The system has been designed to minimize formation damage by forming a thin and ultra-low permeable filter cake. The versatility of the developed polymer allows the new system to be formulated at a wide range of densities using most conventional oilfield brines including monovalent and divalent halide and formate brines.\u0000 The clay-free high temperature drilling fluid has stable rheological properties, no gelation and low sag tendencies which are ideal for high temperature logging applications. Also, the highly branched nature of the polymer provides a rheological profile suitable for coil tubing applications.\u0000 A new breaker package was developed along with the high temperature water-based system to slowly and uniformly clean-up its deposited filter cake, reducing near wellbore damage and maximizing production when the system is used to drill open-hole completion wells.\u0000 This paper summarizes the fluid design in the lab and recent field applications, where the new high temperature polymer-based system was successfully deployed in different locations around the world.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"141 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78441714","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
OBJECTIVES/SCOPE: Please list the objectives and scope of the proposed paper. (25-75 words) PCP population in PDO fields is around 18% of the total Artificial Lift systems with an average runlife of around 360 days. The main cause of failure are tubing leak and sand resulting in parted rods & pump stuck. Continuous PCP surveillance/ monitoring are key to understand pump performance and hence increase their runlife. With this objective, PDO has installed a PCP Controller application / surveillance tool called Well Manager in number of wells on trial basis. METHODS PROCEDURES, PROCESS: Briefly explain your overall approach, including your methods, procedures and process. (75-100 words) In the current set up, PCPs are operated using speed mode and the fluid level checked occasionally using simple fluid shot apparatus whereas with Well Manager they can be operated using different function like production optimization mode, dynamic fluid level or speed control mode all of these modes can be associated with de-sanding function or torque limiting function. These modes to be functional require running downhole gauge, casing pressure, flow line pressure and surface flow rate meters. Surveillance data collected from these meters while these modes are activated has allowed PCPs to automatically optimize their operating conditions to prevent trip due to sand accumulation and pump stuck and therefore increase runlife time. RESULTS, OBSERVATIONS, CONCLUSIONS: Please describe the results, observations and conclusions of the proposed paper. (100-200 words) New PCP setup was installed in well No.1 aiming to reduce solids whilst keeping production rate as it was expected. Well Manager with automated flushing feature every 8 hours, and down hole gauge installed with ant-vibration sub has led for doubling the run life and eliminating FBU interventions. This has resulted in increasing run life from 113 to 239 days and still running. Moreover, compared to the old design in this well, the new set up managed to produce same flow rate using a smaller pump size with lower solids production rate. Another four units installed and showing positive results as well as stability with less well trips and increase in run life. Please explain how this paper will present novel (new) or additive information to the existing body of literature that can be of benefit to a practicing engineer. (25-75 words) The novelty and combination of the Well Manager set up can be replicated and implemented in all PCP wells in the oil industry helping to increase pumps runlife, reduce well intervention cost and oil deferment and therefore, reducing the life cycle cost.
{"title":"PCP PDO Wells Runlife Enhancement Using Well Manager","authors":"A. Mamari","doi":"10.2118/194823-MS","DOIUrl":"https://doi.org/10.2118/194823-MS","url":null,"abstract":"\u0000 OBJECTIVES/SCOPE: Please list the objectives and scope of the proposed paper. (25-75 words) PCP population in PDO fields is around 18% of the total Artificial Lift systems with an average runlife of around 360 days. The main cause of failure are tubing leak and sand resulting in parted rods & pump stuck. Continuous PCP surveillance/ monitoring are key to understand pump performance and hence increase their runlife. With this objective, PDO has installed a PCP Controller application / surveillance tool called Well Manager in number of wells on trial basis. METHODS PROCEDURES, PROCESS: Briefly explain your overall approach, including your methods, procedures and process. (75-100 words) In the current set up, PCPs are operated using speed mode and the fluid level checked occasionally using simple fluid shot apparatus whereas with Well Manager they can be operated using different function like production optimization mode, dynamic fluid level or speed control mode all of these modes can be associated with de-sanding function or torque limiting function. These modes to be functional require running downhole gauge, casing pressure, flow line pressure and surface flow rate meters. Surveillance data collected from these meters while these modes are activated has allowed PCPs to automatically optimize their operating conditions to prevent trip due to sand accumulation and pump stuck and therefore increase runlife time. RESULTS, OBSERVATIONS, CONCLUSIONS: Please describe the results, observations and conclusions of the proposed paper. (100-200 words) New PCP setup was installed in well No.1 aiming to reduce solids whilst keeping production rate as it was expected. Well Manager with automated flushing feature every 8 hours, and down hole gauge installed with ant-vibration sub has led for doubling the run life and eliminating FBU interventions. This has resulted in increasing run life from 113 to 239 days and still running. Moreover, compared to the old design in this well, the new set up managed to produce same flow rate using a smaller pump size with lower solids production rate. Another four units installed and showing positive results as well as stability with less well trips and increase in run life. Please explain how this paper will present novel (new) or additive information to the existing body of literature that can be of benefit to a practicing engineer. (25-75 words) The novelty and combination of the Well Manager set up can be replicated and implemented in all PCP wells in the oil industry helping to increase pumps runlife, reduce well intervention cost and oil deferment and therefore, reducing the life cycle cost.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"19 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82110831","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. O. Eze, O. Ayoola, Baleegh A. Hussain, Humoud H. Khaldi
This paper presents a new insight into the factors that affect the initial productivity of Acid Fracturing (AF) treatments in a sour gas carbonate reservoir. Acid Fracturing is a stimulation technique used to improve the productivity or injectivity of wells. It involves pumping acid into a formation at above fracture pressure, and can treat deep into the formation. Despite the benefits of acid fracturing, conditions are not always favourable for acid fracturing. This could be due to reservoir or well limitations for example, very low formation permeability, formation temperature especially in dolomite formations, and/or well completion integrity. In this application, a total of 12 wells were stimulated after initial completion by acid fracturing. The treatment design is a single stage Pad-Acid treatment which involves pumping 1) pre-acid, 2) gelled water, 3) main acid, 4) diverter, 5) repeat of steps 2 to 4 as required, then followed by 6) a post-acid flush and 7) over-flush. Optimisations made on the treatment design as the campaign progressed include use of specially formulated diversion system, ramp up of acid injection rates and volumes. The analysis of pre and post stimulation productivity performance show the following: An average productivity improvement of 9 times the pre stimulation productivity,A direct relationship between productivity improvement and increasing the rates/volumes of acid injection during the treatment,That treatment volume did not always result to productivity increase but the manner and sequence of fluid injection were of greater effect on productivity.Fluid diversion system blended with particulates show greater increase in productivity than wells treated with diversion systems with no particulates. Based on the results, it can be concluded that, an optimized method of ramping up acid injection rate/volume as well as careful selection of diversion system can lead to productivity improvement of up to 9 times the pretreatment productivity in Carbonate reservoir stimulation.
{"title":"Performance Analysis of Acid Fracturing Treatments in a Sour Gas Carbonate Reservoir","authors":"S. O. Eze, O. Ayoola, Baleegh A. Hussain, Humoud H. Khaldi","doi":"10.2118/194932-MS","DOIUrl":"https://doi.org/10.2118/194932-MS","url":null,"abstract":"\u0000 This paper presents a new insight into the factors that affect the initial productivity of Acid Fracturing (AF) treatments in a sour gas carbonate reservoir.\u0000 Acid Fracturing is a stimulation technique used to improve the productivity or injectivity of wells. It involves pumping acid into a formation at above fracture pressure, and can treat deep into the formation. Despite the benefits of acid fracturing, conditions are not always favourable for acid fracturing. This could be due to reservoir or well limitations for example, very low formation permeability, formation temperature especially in dolomite formations, and/or well completion integrity.\u0000 In this application, a total of 12 wells were stimulated after initial completion by acid fracturing. The treatment design is a single stage Pad-Acid treatment which involves pumping 1) pre-acid, 2) gelled water, 3) main acid, 4) diverter, 5) repeat of steps 2 to 4 as required, then followed by 6) a post-acid flush and 7) over-flush. Optimisations made on the treatment design as the campaign progressed include use of specially formulated diversion system, ramp up of acid injection rates and volumes.\u0000 The analysis of pre and post stimulation productivity performance show the following: An average productivity improvement of 9 times the pre stimulation productivity,A direct relationship between productivity improvement and increasing the rates/volumes of acid injection during the treatment,That treatment volume did not always result to productivity increase but the manner and sequence of fluid injection were of greater effect on productivity.Fluid diversion system blended with particulates show greater increase in productivity than wells treated with diversion systems with no particulates.\u0000 Based on the results, it can be concluded that, an optimized method of ramping up acid injection rate/volume as well as careful selection of diversion system can lead to productivity improvement of up to 9 times the pretreatment productivity in Carbonate reservoir stimulation.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88872854","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
"Would you recommend that your son or daughter go into petroleum engineering?" This is a question SPE presidents and senior executives have been asked for decades and, for most of the last 40 years, the answer has been positive. However, how realistic is a positive response today? In today's society, negative attitudes toward the extractive industries, and fossil fuels in particular, have made the oil & gas industry less attractive to college students. In addition, this negative opinion has been greatly exacerbated by issues surrounding climate change, not to mention the seemingly constant cyclical demand and massive layoffs during downturns. Factor in the inherent pressure for efficiency, new data-driven approaches and AI-based systems and the future of petroleum engineering looks to be quite different from what has been experienced in the past. In addition, decreasing oil demand in American and Europe may well portend radical changes in how the industry functions.
{"title":"The End of Petroleum Engineering as We Know It","authors":"D. Mathieson, D. Meehan, J. Potts","doi":"10.2118/194746-MS","DOIUrl":"https://doi.org/10.2118/194746-MS","url":null,"abstract":"\"Would you recommend that your son or daughter go into petroleum engineering?\" This is a question SPE presidents and senior executives have been asked for decades and, for most of the last 40 years, the answer has been positive. However, how realistic is a positive response today? In today's society, negative attitudes toward the extractive industries, and fossil fuels in particular, have made the oil & gas industry less attractive to college students. In addition, this negative opinion has been greatly exacerbated by issues surrounding climate change, not to mention the seemingly constant cyclical demand and massive layoffs during downturns. Factor in the inherent pressure for efficiency, new data-driven approaches and AI-based systems and the future of petroleum engineering looks to be quite different from what has been experienced in the past. In addition, decreasing oil demand in American and Europe may well portend radical changes in how the industry functions.","PeriodicalId":10908,"journal":{"name":"Day 2 Tue, March 19, 2019","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81026135","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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